This disclosure relates to estimating fluid volumes in a geological formation using multi-dimensional nuclear magnetic resonance (NMR) measurements.
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind.
Producing hydrocarbons from a wellbore drilled into a geological formation is a remarkably complex endeavor. In many cases, decisions involved in hydrocarbon exploration and production may be informed by measurements from downhole well-logging tools that are conveyed deep into the wellbore. The measurements may be used to infer properties and characteristics of the geological formation surrounding the wellbore.
One type of downhole well-logging tool uses nuclear magnetic resonance (NMR) to measure the response of nuclear spins in formation fluids to applied magnetic fields. Many NMR tools have a permanent magnet that produces a static magnetic field at a desired test location (e.g., where the fluid is located). The static magnetic field produces an equilibrium magnetization in the fluid that is aligned with a magnetization vector along the direction of the static magnetic field. A transmitter antenna produces a time-dependent radio frequency magnetic field that is perpendicular to the direction of the static field. The radio frequency magnetic field produces a torque on the magnetization vector that causes it to rotate about the axis of the applied radio frequency magnetic field. The rotation results in the magnetization vector developing a component perpendicular to the direction of the static magnetic field. This causes the magnetization vector to align with the component perpendicular to the direction of the static magnetic field, and to precess around the static field.
The time for the magnetization vector to re-align with the static magnetic field is known as the longitudinal magnetization recovery time, or “T1 relaxation time.” The spins of adjacent atoms precess in tandem synchronization with one another due to the precession of the magnetization vector. The time for the precession of the spins of adjacent atoms to break synchronization is known as the transverse magnetization decay time, or “T2 relaxation time.” Thus, the measurements obtained by downhole NMR tools may include distributions of the first relaxation time T1, the second relaxation time T2, or molecular diffusion, or a combination of these. For example, a downhole NMR tool may measure just T2 distribution, or the tool may measure a joint T1-T2 distribution or T1-T2-D distribution.
Downhole NMR tools are used to obtain a number of formation evaluation measurements. Among other things, downhole NMR tools may be used to evaluate the presence of fluids in the geological formation. In particular, the T1 or T2 distributions may be used for estimation of fluid volumes. One method for fluid volume estimation applies user-specified cutoffs to partition the T2 (or T1) distribution. The cutoffs are determined empirically from core measurements or are based on local knowledge. The application of cutoff-based methodology assumes that the responses of different fluids are independent in the T2 domain.
In many cases, however, the T1 and T2 responses overlap. As such, the cutoff-based methodology may be inaccurate and/or imprecise. Various methods have been proposed to overcome this issue. One of those methods is based on Diffusion-T2 map; however, in the nanometer-size pores of shale reservoirs, the intrinsic T2 relaxation dominates the relaxation mechanism. As a result, accurately measuring diffusion in these reservoirs may be difficult or impossible. Another method involves the use of wet clay porosity (WCLP) and an independent estimate of water saturation to remove the water signal. Yet this method relies on a very accurate value of WCLP, which may involve a core measurement. As such, it may be very difficult to accurately identify fluid volumes using NMR measurements in organic shale reservoirs.